1. Field of the Invention
The present invention relates to a gas turbine control system which can prevent instability in the operation of a gas turbine which occurs when the system frequency increases or decreases in a short time from normal operational frequency due to disconnection of a load, an emergency stop of a generator and so on, and which can prevent an unstable operation as well as stoppage, which is the worst, of the gas turbine as a principal driving source of a thermal power generator, thus contributing to stabilizing the frequency of the electric power system during a transitional period.
2. Description of the Related Art
In gas turbine power generating plants, fuel and compressed air are supplied to a combustor and the combustion gas produced in the combustor is supplied to a gas turbine to operate the same. FIG. 36 shows a schematic view of a gas turbine power generating plant.
A gas turbine unit generally designated by reference numeral 100 in FIG. 36 is composed of a compressor 2, a combustor 4 and a turbine 7. Air introduced into the air compressor 2 through inlet guide vanes or blades 1 is compressed in the compressor 2 into a high-pressure air, which is sent through an air passage 3 into the combustor 4 and used as combustion air for fuel. On the other hand, the fuel is supplied through fuel control valve 5 and a fuel burner 6 into the combustor 4 and combusted therein to produce a combustion gas at high temperature and high pressure. The combustion gas flows into the turbine 7 to rotate a gas turbine shaft 8, which drives a generator 9 to produce output of electric energy. Exhaust gas from the turbine 7 flows directly into a chimney, or, in the case of a combined-cycle power generating plant, flows into a chimney after being used as heat source for an exhaust gas heat recovery boiler.
A gas turbine control device 10 is provided for controlling gas turbine unit 100. The gas turbine control device 10 gives a fuel control signal FREF to the fuel control valve 5 to adjust the fuel flow rate, in response to a gas turbine speed N derived from a gas turbine speed sensor 12 provided adjacent to a gear 11 at the end portion of the gas turbine shaft 8, a compressor inlet air pressure PX1 derived from an inlet air pressure sensor 103 provided adjacent to the inlet portion of the air compressor 2, a compressor outlet air pressure PX2 derived from an outlet air pressure sensor 13 at the outlet portion of the air compressor 2, an exhaust gas temperature TX4 derived from an exhaust gas temperature sensor 14 provided at the outlet portion of the gas turbine 7, and a generator output MW derived from a generator output sensor 15.
FIG. 37 shows a block diagram of the gas turbine control device 10. The control device 10 includes: a speed-load control section 16 that controls the speed of the gas turbine unit 100 and the load of the generator 9 connected to the gas turbine unit 100; combustion gas temperature control section 18 that controls the combustion gas temperature in the gas turbine unit 100 so as to be at or below a predetermined upper limit value; and a fuel control signal selection unit 17 that receives both a speed-load control signal FN from the speed-load control section 16 and an exhaust gas temperature control signal FT from the combustion gas temperature control section 18 and selects a smaller one of these received signals to output it as a fuel control signal. The combustion gas temperature control section 18 shown in FIG. 37 does not control the combustion gas temperature directly but controls the combustion gas temperature indirectly by detecting the temperature TX4 of the exhaust gas from the turbine 7.
The gas turbine unit 100 is started by increasing its rotational speed to a rated rotational speed with the fuel flow rate adjusted at a start control unit not shown. At the start of the turbine, the fuel flow rate is small so that the combustion gas temperature is low, and the speed-load control signal FN from the speed-load control section 16 is smaller than the exhaust gas temperature control signal FT from the combustion gas temperature control section 18. As a result, the speed-load control signal FN is selected at the fuel control signal selection unit 17, as a fuel selection signal FREF. Therefore, the gas turbine, which has increased in speed to the rated rotational speed by the start control unit, is maintained at the rated rotational speed by the speed-load control section 16.
The speed-load control section 16 maintains the gas turbine unit 100 at the rated rotational speed when the generator 9 is not loaded, while when the generator 9 is connected to the electric power system the speed-load control section 16 carries out a control so that the generator 9 outputs a set value in a load setting unit 24. A rated rotational speed is set as an initial set value in a speed setting unit 19 of the speed-load control section 16, and a speed deviation NE from the rotational speed N of the gas turbine unit 100 is calculated in a subtracter 20. Proportional calculation of the speed deviation NE is carried out in a proportional control unit 21, and a no-load rated speed bias signal from a signal generator 22 is added to the proportional-calculated value to generate the speed-load control signal FN. The no-load rated speed bias signal is a signal corresponding to flow rate required to maintain the gas turbine unit 100 and the generator 9 under no-load condition to the rated rotational speed.
When the generator 9 is connected to the electric power system in the above condition, the generator 9 is rotated in synchronism with the system frequency and loaded operation takes place. In the loaded operation, a subtracter 25 calculates a generator output deviation MWE which is the difference between a generator output MW and a load set value in the load setting unit 24. When the generator output deviation MWE is negative, a comparator 26 closes a switch 27, while when the generator output deviation MWE is positive, the comparator 29 closes a switch 30.
When the generator output deviation MWE is negative, a positive value set in a signal generator 28 is input to the speed setting unit 19. The speed setting unit 19 has an integrating characteristic and increases the set value in the speed setting unit 19 at a change rate corresponding to that positive value, thereby changing the speed-load control signal FN so as to make the generator output deviation MWE null. Similarly, when the generator output deviation MWE is positive, the set value in the speed setting unit 19 is reduced at a change rate corresponding to a negative value set in a signal generator 31, thereby changing the speed-load control signal FN so as to make the generator output deviation MWE null.
In a condition in which the generator 9 is connected to the electric power system and is gradually taking a load, the generator output deviation MWE is negative, so that the comparator 27 closes the switch 27 and the set value in the speed setting unit 19 is increased at a change rate corresponding to the positive value set in the signal generator 28, whereby the generator output MW increases gradually. As a result, the exhaust gas temperature TX4 increases gradually and therefore the exhaust gas temperature control signal FT from the combustion gas temperature control section 18 is made smaller gradually.
As the fuel flow rate increases, the exhaust gas temperature TX4 increases, so that an exhaust gas temperature deviation TE decreases gradually. When the exhaust gas temperature TX4 reaches a predetermined upper limit value TXR4, the exhaust gas temperature deviation TE becomes null. When the exhaust gas temperature TX4 exceeds the predetermined upper limit value TXR4, the exhaust gas temperature deviation TE becomes negative, which causes generation of an alarm or trip of the gas turbine unit 100. Due to reduction of the exhaust gas temperature control signal FT, the value of the exhaust gas temperature control signal FT becomes smaller than the value of the speed-load control signal FN. As a result, the fuel control signal selection section 17 replaces the speed-load control signal FN with the exhaust gas temperature control signal FT, which becomes the fuel control signal FREF. Thus, the fuel control signal FREF controls the fuel flow rate to make the exhaust gas temperature TX4 of the turbine unit 100 correspond to the predetermined upper limit value TXR4.
The combustion gas temperature control section 18 has a function generator 32 for calculating an upper limit value TXR4 which is determined as a function of the compressor pressure ratio PX2/PX1. Thus, the combustion gas temperature control section 18 executes a control function to make the exhaust gas temperature TX4 of the turbine 7 equal to the predetermined upper limit value TXR4.
FIGS. 38, 39 and 40 show quantitative changes in the state of the gas turbine unit 100 using the gas turbine control device 10 shown in FIG. 37. As shown in FIG. 38, the fuel flow rate GFX increases in proportion to increase of the generator output MW. Until the generator output MW reaches a time point t1, the angle of the inlet guide vanes or blades 1 is maintained constant by means of an inlet guide vane control device, so that the compressor air flow rate GAX is maintained constant. As the generator output MW increases from the time point t1 through a time point t2 to a time point t3, the angle of the inlet guide vanes or blades 1 is increased gradually by means of the inlet guide vane control device in such a manner that the compressor air flow rate GAX is increased as shown.
As shown in FIG. 39, the combustion gas temperature TX3 increases as the generator output MW increases. When the generator output MW reaches the time point t2, the combustion gas temperature TX3 increases to the upper limit value TXR3. The reason why the compressor air flow rate GAX is maintained constant until the generator output MW reaches the time point t1, is to increase the combustion gas temperature TX3 as quickly as possible, thus raising the thermal efficiency of the gas turbine. Even when the generator output MW increases from the time point t2 to the time point t3, the combustion gas temperature TX3 is maintained at or below the upper limit value TXR3. As the generator output MW increases, the exhaust gas temperature TX4 also increases, and when the generator output MW reaches the time point t1, the exhaust gas temperature TX4 reaches the upper limit value TXR4. Even when the generator output MW increases from the time point t1 to the time point t2, the exhaust gas temperature TX4 is maintained at the upper limit value TXR4 because of the increase in the compressor air flow rate GAX by increasing the angle of the inlet guide vanes or blades 1 and because of the fuel control by the combustion gas temperature control section 18. When the combustion gas temperature TX3 is maintained constant during the increase of the generator output MW from the time point t2 to the time point t3, the exhaust gas temperature TX4 is reduced linearly as shown.
FIG. 40 shows the characteristics of the function generator 32. The compression ratio PX2/PX1 is calculated from the inlet air pressure PX1 of the compressor and the outlet air pressure PX2 of the same, and the exhaust gas temperature upper limit value TXR4 shown in solid line in the figure is generated as a function of the compression ratio PX2/PX1. The control of the exhaust gas temperature TX4 at or below the upper limit value TXR4 by means of the combustion gas temperature control section 18 is equivalent to the maintenance of the combustion gas temperature TX3 at or below the predetermined upper limit value TXR3 as shown in FIG. 39. The broken line in FIG. 40 shows an alarm issuing value for the exhaust gas temperature or a trip value for the gas turbine unit 100.
How the upper limit value TXR3 of the combustion gas is determined will be explained with reference to FIG. 41. This figure shows a relationship between the combustion gas temperature TX3 and a long-term creep strength of a material used for hot gas path parts composing the gas turbine. The temperature of the hot gas path parts increases and decreases in proportion to the temperature of the combustion gas, and the proportional constant is shown as C in this figure. As the combustion gas temperature increases, the long-term creep strength of the material drops. In order to prevent damage of the hot gas path parts, it is required to so control the combustion gas temperature that the creep strength of the material is above a maximum stress produced in the hot gas path parts.
FIG. 41 shows an example in which the upper limit value TXR3 is a value in the case where the long-term of the creep strength is a hundred thousand (100,000) hours. This means that if this value of TXR3 is adopted as the combustion gas upper limit temperature, the hot gas path parts for gas turbines can be used for a hundred thousand (100,000) hours without replacement. The upper limit value TXR4 of the exhaust gas temperature can be determined on the basis of the relationship of TXR3, TXR4 and PX2/PX1 as shown in FIGS. 38 and 39. As stated above, gas turbines that use the conventional gas turbine control device are operated within a range of allowable combustion gas temperature in which hot gas path parts of the gas turbines can be used for a long term without replacement.
The conventional gas turbine control device involves the problem described below. That is, when frequency variations occur in the electric power system, the speed-load control section 16 operates to a great extent to recover the system frequency through a high proportional gain of the proportional control unit 21, so that there occurs a great variation of the fuel flow rate with a resultant great variation of the exhaust gas temperature TX4 of the gas turbine unit 100.
Especially, in a case where a system frequency variation occurs while the gas turbine is operated with the gas turbine exhaust gas temperature TX4 being in the neighborhood of the predetermined upper limit value TXR4, the operation of the speed-load control section 16 gives a large disturbance to the control of the gas turbine fuel and air and the control of the combustion gas temperature. For example, when the system frequency is increased, the gas turbine speed N is also increased. Thus, the speed-load control section 16 operates to correct this, so that the speed-load control signal FN is decreased from the value taken immediately before the system frequency increase. This results in that the speed-load control signal FN is lower than the exhaust gas temperature control signal FT, whereby the speed-load control signal FN is selected in the fuel control signal selecting section 17 and the fuel flow is throttled. Consequently, the fuel flow rate is reduced and the exhaust gas temperature TX4 of the gas turbine unit 100 is reduced with a delay of several seconds.
If the system frequency recovers rapidly in this state, the gas turbine speed N recovers rapidly to the rated rotational speed. In this case, since delay in detecting the gas turbine speed N is negligibly small, so that the speed-load control signal FN increases rapidly. Since the fuel control signal selecting section 17 is selecting the speed-load control signal FN as the fuel control signal FREF in this state, variation in the speed-load control signal FN results in variation in the fuel flow rate and consequently the fuel flow rate increases rapidly. This is because there occurs a delay in increase of the exhaust gas temperature TX4 responsive to the rapid increase of the fuel flow rate due to a several minute delay in detecting the exhaust gas temperature TX4 of the gas turbine unit 100 in relation to the negligible small delay in the detection of the gas turbine speed N.
For this reason, an excessive amount of fuel has been supplied when the exhaust gas temperature TX4 has reached the predetermined upper limit value TXR4 because of the rapid increase of the fuel flow rate. At that time, the fuel control signal selecting section 17 carries out switching from the speed-load control signal FN to the exhaust gas temperature control signal FT as the fuel control signal FREF, to reduce the fuel flow rate. However, since the excessive amount of fuel has already been supplied, the exhaust gas temperature TX4 continues to rise.
For a reason of operation of the gas turbine at high efficiency, the gas turbine unit 100 is run with the combustion gas temperature TX3 maintained at as high a temperature as possible, and therefore the upper limit value TXR4 is close to the alarm issuing value or the gas turbine trip value of the combustion gas temperature TX4. Under such a condition, a further temperature increase sometimes results in an undesirable situation of gas turbine trip. Further, also when the generator output MW is controlled in the condition where the exhaust gas temperature TX4 of the gas turbine unit 100 is somewhat smaller than the upper limit value TXR4 and the speed-load control signal FN is selected as the fuel control signal FREF, an abrupt drop of the system frequency causes the same undesirable situation as stated above since the speed-load control signal FN increases rapidly.
In a large-scale service interruption accident that occurred in Malaysia in 1996, a combined cycle and a gas turbine generator were disconnected successively as a result of trip that occurred in a trunk transmission line. This shows that the power plant in operation under high-load condition became unstable in relation to system frequency reduction. During high-load operation, air flow rate can be increased only slightly because of a limit to the operation of the inlet air guide blades. Furthermore, the fuel supply cannot be increased because trip occurs in the power plant when the gas turbine exhaust gas temperature increases and exceeds a limit value.
The flow rate of air to be supplied is a function of the rotational speed of the gas turbine, and when the system frequency drops, the air flow rate also decreases. Further, there is a limitation to increasing the fuel supply because of the above-mentioned limitation to the exhaust gas temperature of the gas turbine. Therefore, as the system frequency drops, the output of the combined cycle power plant decreases, which causes further drop of the system frequency, leading to a large-scale service interruption. This is reported in a thesis entitled “Dynamic Behavior of Combined Cycle Power Plant during Frequency Drop”, (The transactions of the Institute of Electrical Engineers of Japan, Vol. 122-B, No.3.2002) and in a thesis entitled “Dynamic Study of Power System including Combined Cycle Power Plant” (Thesis No. 6-070, 2002, The Institute of Electrical Engineers of Japan).
In the above situation, the system frequency drops when the generator in operation, connected in parallel to an electric power system is disconnected or when a load such as a generator-motor in the pumped-storage power plant or an induction motor is started. On the other hand, the system frequency increases when the load is disconnected in the system rapidly. During a large-scale system frequency variation in which trip of a combined cycle Power Plant occurs, for example, control is carried out to stabilize the system frequency by disconnecting a load in the system or by adjusting the output of the generator in operation. In this case, it is possible to quickly take a measure to reduce the output of the generator, but increasing the generator output requires several tens seconds depending upon the characteristics of the plant because the output of the exhaust heat recovery boiler must be increased to increase the generator output. Therefore, it is required to provide the gas turbine with a capability of continued operation with as high an output as possible.
It is an object of the present invention to provide a gas turbine control system which contributes to stabilization of the system frequency in cases of transitional or temporary variations of the system frequency without making the strength of hot gas path parts of the gas turbine at below a maximum stress value of the hot gas path parts.